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Hydraulic fracturing is the propagation of fractures in a rock layer by a pressurized fluid. Some hydraulic fractures form naturally certain veins or dikes are examples—and can create conduits along which gas and petroleum from source rocks may migrate to reservoir rocks. Induced hydraulic fracturing or hydrofracturing, commonly known as fracing, fraccing, or fracking, is a technique used to release petroleum, natural gas (including shale gas, tight gas, and coal seam gas), or other substances for extraction. This type of fracturing creates fractures from a wellbore drilled into reservoir rock formations.
The first use of hydraulic fracturing was in 1947. However, it was only in 1998 that modern fracturing technology, referred to as horizontal slickwater fracturing, made possible the economical extraction of shale gas; this new technology was first used in the Barnett Shale in Texas. The energy from the injection of a highly pressurized hydraulic fracturing fluid creates new channels in the rock, which can increase the extraction rates and ultimate recovery of hydrocarbons.
Proponents of hydraulic fracturing point to the economic benefits from vast amounts of formerly inaccessible hydrocarbons the process can extract. Opponents point to potential environmental impacts, including contamination of ground water, risks to air quality, the migration of gases and hydraulic fracturing chemicals to the surface, surface contamination from spills and flowback and the health effects of these. For these reasons hydraulic fracturing has come under scrutiny internationally, with some countries suspending or banning it.
History
Fracturing as a method to stimulate shallow, hard rock oil wells dates back to the 1860s. It was applied by oil producers in the US states of Pennsylvania, New York, Kentucky, and West Virginia by using liquid and later also solidified nitroglycerin. Later, the same method was applied to water and gas wells. The idea to use acid as a nonexplosive fluid for well stimulation was introduced in the 1930s. Due to acid etching, fractures would not close completely and therefore productivity was enhanced. The same phenomenon was discovered with water injection and squeeze cementing operations.
The relationship between well performance and treatment pressures was studied by Floyd Farris of Stanolind Oil and Gas Corporation. This study became a basis of the first hydraulic fracturing experiment, which was conducted in 1947 at the Hugoton gas field in Grant County of southwestern Kansas by Stanolind. For the well treatment 1,000 US gallons (3,800 l; 830 imp gal) of gelled gasoline and sand from the Arkansas River was injected into the gas-producing limestone formation at 2,400 feet (730 m).
The experiment was not very successful as deliverability of the well did not change appreciably. The process was further described by J.B. Clark of Stanolind in his paper published in 1948. A patent on this process was issued in 1949 and an exclusive license was granted to the Halliburton Oil Well Cementing Company. On March 17, 1949, Halliburton performed the first two commercial hydraulic fracturing treatments in Stephens County, Oklahoma, and Archer County, Texas.[15] Since then, hydraulic fracturing has been used to stimulate approximately a million oil and gas wells.
In the Soviet Union, the first hydraulic proppant fracturing was carried out in 1952. In Western Europe in 1977–1985, hydraulic fracturing was conducted at Rotliegend and Carboniferous gas-bearing sandstones in Germany, Netherlands onshore and offshore gas fields, and the United Kingdoms sector of the North Sea. Other countries in Europe and Northern Africa included Norway, the Soviet Union, Poland, Czechoslovakia, Yugoslavia, Hungary, Austria, France, Italy, Bulgaria, Romania, Turkey, Tunisia, and Algeria.
Due to shale’s high porosity and low permeability, technology research, development and demonstration were necessary before hydraulic fracturing could be commercially applied to shale gas deposits. In the 1970s the United States government initiated the Eastern Gas Shales Project, a set of dozens of public-private hydraulic fracturing pilot demonstration projects. During the same period, the Gas Research Institute, a gas industry research consortium, received approval for research and funding from the Federal Energy Regulatory Commission.
In 1977, the Department of Energy pioneered massive hydraulic fracturing in tight sandstone formations. In 1997, based on earlier techniques used by Union Pacific Resources, now part of Anadarko Petroleum Corporation, Mitchell Energy, now part of Devon Energy, developed the hydraulic fracturing technique known as “slickwater fracturing” which involves adding chemicals to water to increase the fluid flow, that made the shale gas extraction economical.
Method A hydraulic fracture is formed by pumping the fracturing fluid into the wellbore at a rate sufficient to increase pressure downhole to exceed that of the fracture gradient (pressure gradient) of the rock. The fracture gradient is defined as the pressure increase per unit of the depth due to its density and it is usually measured in pounds per square inch per foot or bars per meter. The rock cracks and the fracture fluid continues further into the rock, extending the crack still further, and so on.
Operators typically try to maintain “fracture width”, or slow its decline, following treatment by introducing into the injected fluid a proppant – a material such as grains of sand, ceramic, or other particulates, that prevent the fractures from closing when the injection is stopped and the pressure of the fluid is reduced. Consideration of proppant strengths and prevention of proppant failure becomes more important at greater depths where pressure and stresses on fractures are higher. The propped fracture is permeable enough to allow the flow of formation fluids to the well. Formation fluids include gas, oil, salt water, fresh water and fluids introduced to the formation during completion of the well during fracturing.
During the process fracturing fluid leakoff, loss of fracturing fluid from the fracture channel into the surrounding permeable rock occurs. If not controlled properly, it can exceed 70% of the injected volume. This may result in formation matrix damage, adverse formation fluid interactions, or altered fracture geometry and thereby decreased production efficiency.
The location of one or more fractures along the length of the borehole is strictly controlled by various methods that create or seal off holes in the side of the wellbore. Typically, hydraulic fracturing is performed in cased wellbores and the zones to be fractured are accessed by perforating the casing at those locations.
Hydraulic-fracturing equipment used in oil and natural gas fields usually consists of a slurry blender, one or more high-pressure, high-volume fracturing pumps (typically powerful triplex or quintuplex pumps) and a monitoring unit. Associated equipment includes fracturing tanks, one or more units for storage and handling of proppant, high-pressure treating iron, a chemical additive unit (used to accurately monitor chemical addition), low-pressure flexible hoses, and many gauges and meters for flow rate, fluid density, and treating pressure. Fracturing equipment operates over a range of pressures and injection rates, and can reach up to 100 megapascals (15,000 psi) and 265 litres per second (9.4 cu ft/s) (100 barrels per minute).
Fracturing fluids.
Proppants and fracking fluids and List of additives for hydraulic fracturing
High-pressure fracture fluid is injected into the wellbore, with the pressure above the fracture gradient of the rock. The two main purposes of fracturing fluid is to extend fractures and to carry proppant into the formation, the purpose of which is to stay there without damaging the formation or production of the well. Two methods of transporting the proppant in the fluid are used – high-rate and high-viscosity. High-viscosity fracturing tends to cause large dominant fractures, while high-rate (slickwater) fracturing causes small spread-out micro-fractures.
This fracture fluid contains water-soluble gelling agents (such as guar gum) which increase viscosity and efficiently deliver the proppant into the formation.
The fluid injected into the rock is typically a slurry of water, proppants, and chemical additives. Additionally, gels, foams, and compressed gases, including nitrogen, carbon dioxide and air can be injected. Typically, of the fracturing fluid 90% is water and 9.5% is sand with the chemical additives accounting to about 0.5%.
A proppant is a material that will keep an induced hydraulic fracture open, during or following a fracturing treatment, and can be gel, foam, or slickwater-based. Fluids make tradeoffs in such material properties as viscosity, where more viscous fluids can carry more concentrated proppant; the energy or pressure demands to maintain a certain flux pump rate (flow velocity) that will conduct the proppant appropriately; pH, various rheological factors, among others. Types of proppant include silica sand, resin-coated sand, and man-made ceramics.
These vary depending on the type of permeability or grain strength needed. The most commonly used proppant is silica sand, though proppants of uniform size and shape, such as a ceramic proppant, is believed to be more effective. Due to a higher porosity within the fracture, a greater amount of oil and natural gas is liberated.
The fracturing fluid varies in composition depending on the type of fracturing used, the conditions of the specific well being fractured, and the water characteristics. A typical fracture treatment uses between 3 and 12 additive chemicals. Although there may be unconventional fracturing fluids, the typical used chemical additives are:
•Acids—hydrochloric acid (usually 28%-5%), or acetic acid is used in the pre-fracturing stage for cleaning the perforations and initiating fissure in the near-wellbore rock.
•Sodium chloride (salt)—delays breakdown of the gel polymer chains.
•Polyacrylamide and other friction reducers—minimizes the friction between fluid and pipe, thus allowing the pumps to pump at a higher rate without having greater pressure on the surface. Polyacrylamide are good suspension agents ensuring the proppant does not fall out.
• Ethylene glycol—prevents formation of scale deposits in the pipe.
•Borate salts—used for maintaining fluid viscosity during the temperature increase.
•Sodium and potassium carbonates—used for maintaining effectiveness of crosslinkers.
•Glutaraldehyde—used as disinfectant of the water (bacteria elimination).
•Guar gum and other water-soluble gelling agents—increases viscosity of the fracturing fluid to deliver more efficiently the proppant into the formation.
•Citric acid—used for corrosion prevention.
•Isopropanol—increases the viscosity of the fracture fluid.
The most common chemical used for hydraulic fracturing in the United States in 2005–2009 was methanol, while some other most widely used chemicals were isopropyl alcohol, 2-butoxyethanol, and ethylene glycol.
Typical fluid types.
• Conventional linear gels. These gels are cellulose derivatives (carboxymethyl cellulose, hydroxyethyl cellulose, carboxymethyl hydroxyethyl cellulose, hydroxypropyl cellulose, methyl hydroxyl ethyl cellulose), guar or its derivatives (hydroxypropyl guar, carboxymethyl hydroxypropyl guar) based, with other chemicals providing the necessary chemistry for the desired results.
•Borate-crosslinked fluids. These are guar-based fluids cross-linked with boron ions (from aqueous borax/boric acid solution). These gels have higher viscosity at pH 9 onwards and are used to carry proppants. After the fracturing job the pH is reduced to 3–4 so that the cross-links are broken and the gel is less viscous and can be pumped out.
•Organometallic-crosslinked fluids zirconium, chromium, antimony, titanium salts are known to crosslink the guar based gels. The crosslinking mechanism is not reversible. So once the proppant is pumped down along with the cross-linked gel, the fracturing part is done. The gels are broken down with appropriate breakers.
•Aluminium phosphate-ester oil gels. Aluminium phosphate and ester oils are slurried to form cross-linked gel. These are one of the first known gelling systems.
For slickwater it is common to include sweeps or a reduction in the proppant concentration temporarily to ensure the well is not overwhelmed with proppant causing a screen-off. As the fracturing process proceeds, viscosity reducing agents such as oxidizers and enzyme breakers are sometimes then added to the fracturing fluid to deactivate the gelling agents and encourage flowback. The oxidizer reacts with the gel to break it down, reducing the fluid’s viscosity and ensuring that no proppant is pulled from the formation.
An enzyme acts as a catalyst for the breaking down of the gel. Sometimes pH modifiers are used to break down the crosslink at the end of a hydraulic fracturing job, since many require a pH buffer system to stay viscous. At the end of the job the well is commonly flushed with water (sometimes blended with a friction reducing chemical) under pressure.
Injected fluid is to some degree recovered and is managed by several methods, such as underground injection control, treatment and discharge, recycling, or temporary storage in pits or containers while new technology is being continually being developed and improved to better handle waste water and improve re-usability.
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The product of concentration and time (CT) is the most important operational parameter in disinfection and inactivation. Although increasing the dose increases the ability of chlorine to oxidize and disinfect, it may also lead to taste and odor issues and to the formation of disinfection byproducts (DBPs) by chlorine’s reaction with natural organic matter (NOM). The dose is also affected by the application point, chlorine demand of the water, and desired residual concentration. Total organic carbon (TOC) and ultraviolet absorbance (UV) are two measures of DBP-reactive NOM and of chlorine demand. Information courtesy of EPA 
